Piezo-based downhole flow meter

ABSTRACT

A flow meter is provided for disposing downhole in a well. The flow meter includes a resonator beam that is integrated with piezo-material to generate a voltage in response to the downhole flow. A resonator head may be incorporated with the resonator beam so as to enhance the generated voltage where appropriate. Configurations of flow meters employing such piezo-material may substantially avoid the use of moving parts susceptible to corrosion and other downhole conditions. These configurations may be particularly useful for long term downhole use such as for production monitoring.

BACKGROUND

1. Technical Field

Embodiments described generally relate to flow meters for use in hydrocarbon wells. In particular, some embodiments of flow meters are detailed that are configured for long-term downhole disposal in hydrocarbon wells. Such flow meters may be well suited for use in conjunction with completion and production operations, although other operations may also be appropriate. Although a field has been described, this is primarily for the non-limiting purposes of simplifying the detailed description. Aspects and concepts detailed herein may apply to other related and non-related fields and applications.

2. Description of the Related Art

The following descriptions and examples are not admitted to be prior art by virtue of their inclusion in this section.

Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. In recognition of the potentially enormous expense of well completion, added emphasis has been placed on well monitoring and maintenance throughout the life of the well. That is, placing added emphasis on increasing the life and productivity of a given well may help ensure that the well provides a healthy return on the significant investment involved in its completion. Thus, over the years, well diagnostics and treatment have become more sophisticated and critical facets of managing well operations.

In certain circumstances, well diagnostics takes place on a near-continuous basis such as where pressure, temperature or other sensors are disposed downhole, for example, in conjunction with production tubing. That is, a monitoring tool with sensors may be affixed downhole with tubing in order to track well conditions during hydrocarbon recovery. In some cases, the monitoring tools may be fairly sophisticated with capacity to simultaneously track a host of well conditions in real time. Thus, both sudden production profile changes and more gradual production changes over time may be accurately monitored. Such monitoring allows for informed interventions or other adjustments where appropriate.

Monitoring tools as noted above are often equipped with flow meters in order to keep track of downhole fluid flow. Ultimately, continuous monitoring of downhole fluid flow may be a fairly direct indicator of the hydrocarbon recovery rate for a given well. The flow meter itself may be of a host of different variations. Some of the more common examples in the oilfield industry include rotameters, mass flow meters, electromagnetic flow meters, and venturi meters.

Unfortunately, the accuracy of the flow meters noted above may be severely affected by particular downhole conditions. For example, high turbulence and pressure variations may substantially affect flow meter readings for the variations noted above. Additionally, rotameters and mass flow meters are also particularly susceptible to variations in downhole fluid type. That is, the more the fluid flow varies over time in consistency in terms of water, hydrocarbon, gas bubbles, etc., the more unreliable the readings obtained by rotameters and mass flow meters. Thus, given the naturally variable and often turbulent conditions of the downhole environment, readings obtained with the noted flow meters are often compromised.

As an alternative to the above noted flow meter types, turbine meters are often incorporated into the monitoring tool. Like some other flow meter types, the turbine flow meter includes a cylindrical housing that defines a central channel through which downhole fluids may flow. However, the turbine based flow meter also includes at least one rotable turbine that is exposed to the central channel and any fluid flow there through. As such, the rate of rotation of the turbine blade may be utilized to continuously monitor flow rate through the flow meter.

The described turbine flow meter relies primarily on mechanical parts configured to display a great deal of movement (i.e. a rotating turbine blade). Additionally, the turbine flow meter is often employed downhole on a long term or near permanent basis, for example, following well completions. Unfortunately, given that the interior of the meter is configured for exposure to the well, this means that the meter is naturally subject to a great deal of corrosion and other undesirable buildup over time. Thus, unlike a more solid-state type of flow meter, such as a venturi meter, the turbine flow meter, is particularly susceptible to deterioration over time. That is, as corrosion takes effect at the surfaces of the turbine blade and supportive features, the ability of the turbine to rotate is markedly affected. Ultimately, the operator is again left with a compromised flow-meter option in terms of long term post completion deployment.

SUMMARY

A meter for measuring downhole flow in a well is provided. The meter may include a cylindrical housing with a resonator beam secured to a wall thereof. The beam may extend into a channel through the housing and is integrated with piezo-material so as to generate a voltage in response to channeled flow induced vibration of the beam.

Other or alternative features will become apparent from the following description, from the drawings, and from the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

Certain embodiments of the invention will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood, however, that the accompanying drawings illustrate only the various implementations described herein and are not meant to limit the scope of various technologies described herein. The drawings are as follows:

FIG. 1 is an enlarged sectional view of an illustrative embodiment of a piezo-based downhole flow meter employing a resonator beam and taken from 1-1 of FIG. 2;

FIG. 2 is an overview of a production assembly disposed in a well at an oilfield with the piezo-based downhole flow meter of FIG. 1;

FIG. 3A is a side sectional view of an alternate embodiment of a piezo-based downhole flow meter employing the resonator beam with a head;

FIG. 3B is a side sectional view of exemplary alternate resonator beam configurations employable with embodiments of piezo-based downhole flow meters;

FIG. 4A is a side sectional view of another alternate embodiment employing a lagging beam assembly centrally disposed in the piezo-based flow meter;

FIG. 4B is a side sectional view of yet another alternate embodiment employing a leading beam assembly centrally disposed in the piezo-based flow meter; and

FIG. 5 is a flow-chart summarizing an embodiment of employing a piezo-based downhole flow meter.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those of ordinary skill in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described illustrative embodiments may be possible. In the specification and appended claims: the terms “connect”, “connection”, “connected”, “in connection with”, “connecting”, “couple”, “coupled”, “coupled with”, and “coupling” are used to mean “in direct connection with” or “in connection with via another element”; and the term “set” is used to mean “one element” or “more than one element”. As used herein, the terms “up” and “down”, “upper” and “lower”, “upwardly” and downwardly”, “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments.

Embodiments are described with reference to certain types of downhole hydrocarbon recovery operations. In particular, focus is drawn to flow meter tools and techniques which may be employed in conjunction with completion assemblies or production tubing. However, tools and techniques detailed herein may be employed in a variety of other hydrocarbon operations. These may include the use of a piezo-based downhole flow-meter in operations ranging from logging to well treatments, including a variety of interventional applications. Regardless, embodiments of flow-meters described herein are configured to acquire downhole flow data through a piezo-material integrated resonator beam. The resonator beam is configured to impart a flow generated voltage uphole which may be utilized in establishing downhole flow characteristics.

Referring now to FIGS. 1 and 2, an embodiment of a piezo-based flow meter 100 is shown disposed in a conventional 10-12 inch diameter well 180. Although, in other embodiments, a host of different well sizes may be utilized. The flow meter 100 is positioned as shown so as to detect flow (see arrows 160). This flow 160 may include water, hydrocarbons, gas bubbles, or any other downhole fluids and constituents thereof. In the embodiment shown, the flow meter 100 is positioned near the end of production tubing 285. However, in one alternate embodiment the flow meter 100 may be anchored to a casing 185 of the well 180. Regardless, the flow meter 100 may be configured to remain a near permanent downhole fixture. Thus, the flow meter 100 may be utilized to track flow 160 throughout the productive life of the well 180. Of course, as noted above, in alternate embodiments the piezo-based flow meter 100 may be utilized in other downhole applications such as logging.

With particular reference to FIG. 1, an enlarged sectional view of the piezo-based flow meter 100 is shown taken from 1-1 of FIG. 2. In this view, the flow meter 100 is shown defining the end of production tubing 285 and positioned relatively close to the production region 297 of the adjacent formation 195 (see FIG. 2). However, in other embodiments, the flow meter 100 may be a substantial distance uphole of the noted region 297. Additionally, in the embodiment shown, the flow meter 100 may be large enough to substantially avoid interference with production and allow follow on access through the tubing 285 and meter 100.

Continuing with reference to FIG. 1, the piezo-based flow meter 100 includes an inlet portion 125 and an outlet portion 175 along with a middle portion or belly 140 disposed there between. Together, these features 125, 140, 175 make up a substantially cylindrical housing which defines a channel through which flow 160 may pass. A resonator device such as a resonator beam 101 is also provided which extends into this channel in order to interface with the noted flow 160. Vortex shedding 310 of the flow 160 may thereby result in a manner that mechanically vibrates or resonates through the beam 101 (see also FIG. 3). As further described below, the beam 101 may be integrated with piezo-material so as to take advantage of such resonance and therefore acquire flow data in the form of generated voltage. For example, in the embodiment shown a discrete piezo-material portion 102 may be located at the base of the beam 101. However, other configurations of beam 101 and piezo-material portions 102 may be employed.

As indicated above, the resonator beam 101 may be integrated with piezo-material portion 102. The piezo-material may include conventional polymer or co-polymer voltage responsive materials such as polyvinylidene fluoride, among others. Additionally, voltage responsive ceramics such as lead zirconate may be employed. Regardless of the type of material, the piezo-material may be implemented at the beam 101, for example, as an integrated coating such as piezo-material portion 102. Thus, vibration of the beam 101 due to flow 160 may result in voltage generation as is expected with such materials. In the embodiment shown, this generated voltage may be picked up by an electrical line 150 terminally immersed in or electrically coupled to the piezo-material portion 102. As such, the generated voltage signal may be transmitted uphole, ultimately providing information corresponding to flow 160. As detailed further below, a variety of techniques may be employed for advancing and translating of this electrical signal in a manner that results in usable flow information.

In addition to the exemplary features noted above, the depicted flow-meter 100 may be provided with a configuration in which the diameter d at the inlet 125 and outlet 175 is smaller than the diameter D of the middle portion or belly 140. As a result, the overall profile of the flow meter 100 in the well 180 may reduced as compared to a uniform diameter configuration. Perhaps more significant however, the smaller diameter d of the inlet 125 relative to the belly 140 may be employed so as to reduce the speed of flow 160 in the area within the middle portion of the flow meter 100. Thus, the rate or speed of flow 160 at the belly 140, where the resonator beam 101 is located, may be reduced to a more manageable level as described below.

In one embodiment, the diameter d of the inlet 125 may be between about ½ and about 3 inches. In this situation, the diameter D of the belly 140 may be between about 5 and about 6 inches (with the beam 101 extending between about 2 and 3 inches into a central portion of the belly 140). Of course, however, the differences between the diameters d, D may be larger, smaller, or non-existent all together, depending upon the expected nature and flow conditions of the well 180. Regardless, the data obtained from the flow meter 100 may be evaluated and calibrated in light of the particular sizing and flow meter configuration employed.

In an alternate embodiment where flow rate is relatively low, a flow meter 100 may be disposed downhole that employs a larger diameter d inlet 125 as compared to the diameter D of the belly 140. So, for example, in this case, the inlet 125 may be of a diameter d that is between about 5 and about 6 inches, whereas the diameter D of the belly 140 may be reduced down to between about ½ and about 3 inches. Such an embodiment of flow meter 100 may be utilized in conjunction with a logging operation following a sudden loss of production. With a flow meter 100 having such a configuration, the rate of flow 160 may be increased at the location of the resonance beam 101 so as to acquire meaningful flow readings during the log. Of course, embodiments of the flow meter 100 may be configured such that the expected or actual flow rate proximate to the resonance beam 101 is adjusted to match an optimal frequency for the resonance beam 101, such that overall sensitivity of the flow meter 100 is enhanced.

In the embodiment of FIG. 1 described above, the flow meter 100 defines the terminal end of production tubing 285 (see FIG. 2). However, in alternate embodiments, the flow meter 100 may be coupled to the well casing 185 near the terminal end of production tubing. For example, the belly 140 of the flow-meter 100 may be secured at a recess of the well casing 185 with the inlet 125 and outlet 175 portions of the meter 100 remaining fully outside of the recess, such as may be the case with a polished bore receptacle (as a recess) and a seal surrounding the exterior of the belly 140 in sealing contact with the recess of the well casing 185. Of course, other embodiments may provide for a gap between the interior surface of the recess and the exterior surface of the belly 140 of the flow meter. Thus, flow 160 channeled through the flow meter 100 would remain largely unaffected in spite of this particular manner of securing the meter 100 downhole. In another alternate embodiment, the flow meter 100 may be secured at a lengthy section of casing 185 having an enlarged diameter relative to other adjacent casing 185. As described below, this may be done in order to secure the flow meter 100 at an out of the way location that is unlikely to interfere with potential future downhole logging, interventions, etc.

The above-noted embodiment of lengthy section of enlarged casing 185 may be of a diameter that exceeds other adjacent casing 185 by at least the profile of the entire flow meter 100. For example, consider a flow meter 100 of a diameter of less than about 3 inches (e.g. at its belly 140) which is disposed within a generally 10 inch well 180. In such a circumstance, the enlarged section of casing 185 may be about 16 inches or more so as to fully remove the flow meter 100 secured there at from the main channel of the well 180. That is, as compared to the smaller adjacent casing 185, an extra three inches of accommodating diameter may be present at the enlarged section of casing 185. Furthermore, in order to ensure that flow 160 is computable and properly accounted for by the meter 100 at the enlarged section of casing 185, this enlarged section may be of a substantial length. For example, in one embodiment, the enlarged section of casing 185 may be of a length that is between about 7 and about 15 times the diameter of the inlet portion 125 of the flow meter 100.

Continuing now with reference to FIG. 2, an overview of well operations at an oilfield 200 is shown. Namely, a side sectional view of the well 180 of FIG. 1 is shown traversing formation layers 195, 295 to reach a production region 297 with outwardly extending perforation channels 298. Production tubing 285 is run to an area adjacent the production region 297 for hydrocarbon recovery and the above described piezo-based flow meter 100 is provided to track downhole flow rates in real-time. Accordingly, a direct measure of recovery may be made available during production operations.

In the overview of FIG. 2, a host of surface equipment 250 is shown disposed at the oilfield 200. Namely, a rig 210 is provided immediately over the well 180 to support initial drilling and subsequent access applications. The well 180 is capped by a well head 220, which may or may not be of a standard Christmas-tree configuration. A production line 230 is coupled to the well head 220. The line 230 may be coupled to a pump and other equipment for directing and transporting recovered fluids out of, and away from, the well 180. A control unit 240 is also provided which may be utilized to direct surface pumps and other equipment. As detailed further below, the control unit 240 may also be communicatively coupled to the downhole flow meter 100 for acquiring, storing, and/or employing flow data obtained there from. In some embodiments, the control unit 240 may be equipped to transmit flow data and other information to a centralized off site location where a host of producing wells may be simultaneously monitored, for example.

The production tubing 285 is run to a location of the well 180 adjacent the production region 297 where it may be isolated by a packer assembly 275. This assembly 275 provides a sealing engagement between the tubing 285 and the wall of the well casing 185. As a result, any uphole flow 160 is directed through the production tubing 285 to the surface. With this in mind, the flow meter 100 located near the end of the production tubing 285 should acquire a direct measure of the total downhole flow 160. With added reference to FIG. 1, an electrical line 150 is run from the flow meter 100 in an uphole direction, traversing the packer assembly 275 and ultimately allowing for flow data collection by the control unit 240 as described above. However, as detailed further below, intervening data storage and conversions may take place. Indeed, the line 150 may be largely replaced by fiber optic line or other communications technology where appropriate.

Referring now to FIG. 3A, a side sectional view of an alternate embodiment of a piezo-based flow meter 300 is depicted which employs a resonator head 325 at the extended end of the resonator beam 101. Additionally, in this illustrative depiction, the electrical line 150 running from the flow meter 300 is shown communicatively coupling to a data unit 350, configured to obtain voltage flow data. In some embodiments the data unit 350 may include an opto-electric converter board and processor. A battery and light source, such as a conventional LED, may also be included. In this manner, the voltage data obtained by the unit 350 may be converted to light signal for transmitting further uphole over a fiber optic line 375.

The fiber optic communication line 375 may be equipped with a protective jacket of stainless steel or other suitable corrosion resistant material. Nevertheless, the line 375 may be substantially smaller in diameter and lighter than a conventional electronic cable with metal conductive core. For example, in some embodiments the line 375 may have an outer diameter of less than about 0.25 inches. Given the minimal amount of available well 180 space and a potential distance to the surface of several thousand feet, use of a smaller diameter, lighter weight communication line may be of significant benefit.

Upon reaching the surface, the light signal may be received by the control unit 240 and converted back into usable electronic data with an opto-electric converter of the unit 240. In other embodiments where the flow meter 300 is positioned closer to surface, the data unit 350 may be equipped with a wireless transceiver for wireless communication with the control unit 240. Alternatively, the data unit 350 and the flow meter 300 may be provided as part of a basic logging tool or other form of access assembly that is not intended to utilize flow measurements in real-time. In such an embodiment, the data unit 350 may serve as a data storage unit from which flow data may be acquired and utilized at a later point in time (e.g. following an application with the tool or assembly).

Continuing with reference to FIG. 3A, vortex shedding 310 of the flow 160 through the flow meter 300 may be realized as previously described. In the embodiment of FIG. 3A, however, a resonator head 325 may be provided at the extended end of the resonator beam 101 so as to amplify the resulting resonance or otherwise increase the sensitivity thereof. In the embodiment shown the head 325 is of a cylindrical shape and oriented with its outer diameter surface facing the flow 160 so as to maximize any resonating effects thereof on the beam 101. In this manner, amplification may be attained with a relatively lightweight, hollowed out feature. As such, the possibility of the mass of the head 325 dampening or reducing the amount of amplified resonance is minimized. In an embodiment similar to that of FIG. 1, with the inlet 125 having a diameter of between about ½ and about 3 inches, the belly 140 having a diameter of between about 5 and about 6 inches, and the beam 101 being between about 2 and 3 inches long, the head 325 may have a diameter of up to about 2 inches.

Referring now to FIG. 3B, a non-limiting collection of alternative beam 101 cross-sectional configurations is shown, although other cross-sectional configurations may be used as appropriate. The collection provides a series of alternate configurations of resonator beams 301, 302, 303, 304 that may be employed in measuring flow 160. In these embodiments, the beams 301, 302, 303, 304 continue to be incorporated with piezo-material as previously detailed. However, depending on a host of factors such as anticipated downhole flow rates, flow-meter sizing, and other factors, the resonance or frequency through the beam 301, 302, 303, 304, may be optimized by utilization of alternate beam shapes as described below.

Each of the above described beams 301, 302, 303, 304 of FIG. 3A may be equipped with a face 311, 312, 313, 314 for interacting with the fluid flow 160. In some cases, the face may be a relatively flat face, such as in beams 311, 312, 313, or fairly arcuate with a convex surface 314, or a combination of various geometric shapes and surfaces configured to interface with the flow 160. Additionally, other circumstances may benefit by providing the flat face 311, 312, 313 with a counterbalancing projection 321, 323 extending there from. Embodiments of the flat face 311, 312, 313 may also be coupled to a stabilizing portion 322, 333 which may also be secured to the inner wall of the flow meter 300 so as to reinforce the beam 302, 303 (see FIG. 3A). Regardless of the particular configuration of beam 301, 302, 303, 304 selected, the shape may be calibrated and accounted for in the final computational analysis converting generated voltage into flow measurements.

Referring now to FIG. 4A, a side sectional view of another alternate embodiment of flow meter 400 is depicted. In this illustrative embodiment, a lagging beam assembly 425 is employed which suspends the resonator beam 401 centrally within the flow meter 400. A 3-legged support structure 430 (only two legs may be seen in this view) is secured to the inner wall 435 of the meter 400 so as to locate the beam 401 within the fluid flow 160, although other configurations of support structures may be employed. Additionally, this configuration orients the beam 401 substantially parallel with the flow 160 (as opposed to the comparatively perpendicular orientation depicted in the embodiments of FIGS. 1 and 3A).

Due to the parallel orientation of the beam 401 relative to the flow 160, flow induced vibration of the beam 401 is primarily dependent upon a resonator head 440. That is, the resonator head 440 is positioned at the lagging end (downstream) of the beam 401. Relative to the previous illustrative embodiment, any vortex shedding 310 (as seen in FIG. 3A) may not substantially occur until the flow 160 reaches the resonator head 440. Of course, the configuration of the resonator head 440 may be determined based upon some of the factors discussed with reference to the configuration of the beams 301-304 as well as other shapes shown to facilitate vortex shedding.

FIG. 4B reveals yet another alternate embodiment of piezo-based flow meter 450. In this case, a leading beam assembly 426 is employed. This exemplary embodiment centrally disposes the resonator beam 411 within the flow meter 450 via a support structure 431 (e.g., a three legged structure, but only two legs are shown in this view) coupled to the inner wall 436 of the flow meter 450. As with the previous embodiment, the beam 411 may be oriented parallel to the flow 160. However, in this case, the assembly 426 is reversed with the resonator head 441 positioned to interface the flow 160 in advance (upstream) of the beam 411 or support structure 431.

The leading orientation or upstream configuration of the resonator head 441 avoids any potential shedding interference resulting from the support structure 431 interfacing the flow 160 in advance of the resonator features 441, 411. That is, with such an orientation, the resonator features 441, 411 are ensured to interface and interact with a relatively undisturbed fluid flow 160. Further, regardless of the configuration of the resonator head 411, a leading orientation provides the detecting components (i.e., 441, 411) of the flow meter 450 with an inherent natural instability that may enhance sensitivity to the fluid flow 160. Accordingly, even a substantially low flow rate is likely to generate a detectable frequency in the beam 411 sufficient for voltage generation by an associated piezo-material. Such an embodiment of flow meter 450 may be especially useful in low flow operations when incorporated into a logging tool.

Referring now to FIG. 5, a flow-chart is depicted which summarizes an illustrative embodiment of a method of employing a piezo-based downhole flow meter such as those detailed above. As indicated at 520, the flow meter is positioned downhole, for example, on a long term basis to monitor flow rate in a completed and producing well. However, in alternate embodiments, the flow meter may be utilized as part of a logging tool or in conjunction with some other shorter term application. Regardless, as indicated at 530 and 540, the speed of flow into the flow meter may be adjusted to a manageable level for measurements. For example, the cylindrical shape of the flow meter may include a smaller inlet relative to the remaining cylindrical body of the flow meter so as to reduce flow there into. Alternatively, the inlet may be larger than the remainder of the body so as to increase flow for measurement purposes.

A resonator beam within the flow meter may then be exposed to flow as indicated at 550 so as to generate a vibrational frequency in the beam. With the beam vibrating, a piezo-material integrated with the beam may be utilized to generate voltage data corresponding to flow rate as indicated at 570. This data may then be analyzed to determine the flow rate (see 580).

Embodiments described herein include a flow meter for use in the downhole environment of a well without the reliance on a rotating turbine blade or other substantial moving parts. Rather, the flow meter may be substantially solid state in nature in that a cohesive structure may be provided. Thus, unlike a turbine-based flow meter, embodiments detailed herein may be particularly beneficial for disposal in a well for near permanent monitoring of downhole flow rate. That is, embodiments described herein may be provided with an inherent degree of corrosion resistance and are not particularly susceptible to the buildup of debris as may be the case of flow meters employing rotating turbine blades. As a result, substantially reliable flow monitoring over extended periods of time may be achieved with aspects of the described embodiments of representative flow meters.

The preceding description has been presented with reference to presently preferred embodiments. However, other embodiments not detailed herein may be employed. Furthermore, persons skilled in the art and technology to which these embodiments pertain will appreciate that still other alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle and scope of these embodiments. Furthermore, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope. 

1. A flow meter for measuring downhole flow in a well, the flow meter comprising: a cylindrical housing defining a channel there through for accommodating flow; a resonator beam coupled to a surface of said cylindrical housing and having a portion disposed in the channel; and a piezo-material integrated with said resonator beam and configured to generate a voltage corresponding to flow induced vibrating of said resonator beam.
 2. The flow meter of claim 1 wherein said cylindrical housing comprises contiguous inlet and belly portions defining the channel, said inlet portion configured to direct the flow, and said belly portion of a different diameter than said inlet portion.
 3. The flow meter of claim 2 wherein the diameter of said belly portion is larger than the diameter of said inlet portion.
 4. The flow meter of claim 1 wherein the piezo-material is one of a polymer, co-polymer or ceramic.
 5. The flow meter of claim 1 wherein said resonator beam comprises a face configured to increase sensitivity of the flow induced vibrating to the downhole flow.
 6. The flow meter of claim 5 wherein said face is of a shape that is substantially flat and substantially perpendicular to an influx of the downhole flow.
 7. A flow meter for measuring downhole flow in a well, the meter comprising: a cylindrical housing defining a channel there through for accommodating flow; a resonator beam coupled to a surface of said housing and having a portion disposed in said channel; and a resonator head coupled to said beam to amplify vibrating thereof in response to the downhole flow.
 8. The flow meter of claim 7 wherein said resonator beam is integrated with piezo-material configured to generate a voltage in response to the vibrating of the resonator head.
 9. The flow meter of claim 7 wherein said resonator head is of a cylindrical shape.
 10. The flow meter of claim 7 further comprising a support structure secured to the surface of the cylindrical housing and configured to centrally dispose said beam in the channel substantially parallel to the downhole flow.
 11. The flow meter of claim 10 wherein said resonator head is configured to interface the downhole flow in a leading configuration relative to said support structure.
 12. The flow meter of claim 7 wherein the resonator head is configured with a fluid dynamic shape.
 13. An assembly for monitoring flow in a well at an oilfield, the assembly comprising: a downhole flow meter with a piezo-integrated beam for interfacing flow accommodated by said flow meter; and a unit communicatively coupled to said meter to obtain flow data corresponding to voltage generated by piezo-material of the piezo-integrated beam in response to the interfacing the flow.
 14. The assembly of claim 13 wherein said unit is a downhole data unit adjacent said flow meter.
 15. The assembly of claim 13 wherein said unit is a data unit electrically coupled to said flow meter, the assembly further comprising a control unit at a surface of the oilfield adjacent the well and fiber optically coupled to said data unit.
 16. A method of monitoring downhole fluid flow in a well, the method comprising: positioning a flow meter downhole in the well; exposing a resonator device of the flow meter to flow accommodated thereby to generate a vibrational frequency; and employing piezo-material of the beam to generate voltage flow data in response to the vibrational frequency.
 17. The method of claim 16 further comprising utilizing a resonator head of the resonator device to amplify the vibrational frequency for enhancing the voltage flow data.
 18. The method of claim 16 wherein said positioning further comprises advancing the flow meter through the well as part of a logging application. 